In known drilling methods, the rock is destroyed by rolling cutters on a drill bit or by stationary cutting surfaces such as in drag bits or diamond bits. This mechanical destruction of the rock produces debris which has to be removed as it is formed so that the bit is constantly operating on new rock.
To remove the debris being formed during drilling, a drilling fluid is circulated through the well as it is drilled. Bits incorporate nozzles which direct the drilling fluid (or mud) to the hole-bottom. A typical rock drilling bit has three rotating cutters with three nozzles arranged around the cutters. A fourth centrally placed nozzle is also available on some drill bits. Other bits can have as few as two or more than four nozzles. The drilling fluid is in constant circulation while drilling and has several basic functions. The circulating drilling fluid maintains higher pressure in the wellbore than in the surrounding rock to prevent formation fluid(s) from entering the wellbore. The circulating fluid also cools the drill bit, cleans the cutters, and removes the rock debris from the bottom of the hole.
The hydraulic system of a drilling well controls the speed and pressure of the circulating mud and an optimized hydraulic system can improve the drilling rate, reduce equipment inefficiencies and lower drilling costs. The hydraulic system is controlled by four different factors. The first is the surface pumps which circulate the drilling fluid down the pipe, through the bit nozzles, back up the annulus, and back down the pipe. The second is the loss in pressure caused by friction as the drilling fluid goes down the pipe. A third factor is the pressure loss at the drill bit which occurs when the drilling fluid leaves the drill bit nozzles and the fourth is the pressure loss in the annulus which occurs as the drilling fluid is circulated back up the annulus to the surface to be recirculated back down the pipe. A comprehensive discussion of well hydraulics can be found in J. S. Short, Drilling and Casing Operations, Tulsa, Okla., PennWell Publishing Company, p. 241-248, TN871.2S537, and numerous other drilling publications.
The pressure loss that occurs at the drill bit, is largely dependent upon the diameter of the nozzles placed in the drill bit prior to drilling for a given mud weight and mud flow rate. Thus, the larger the diameter of nozzles used, the less of a pressure drop at the bit, which results in a decrease in fluid velocity as the mud exits the nozzles. Conversely, the smaller the diameter, the greater the pressure drop at the bit, which results in an increase in fluid velocity as the mud exits the nozzles.
The diameters of the nozzles determine the total flow area (TFA) of a bit. The TFA of a bit is equal to the sum of the flow areas of the nozzles in the bit. The appropriate total flow area for any given drill bit is determined by the depth of the well, the drilling assembly used, the drilling fluid characteristics, and the hydraulic system's flow rate. Currently, when a drill bit TFA needs to be increased or decreased, drilling is stopped, the drill bit is removed from the well and the nozzles are replaced.
When drilling is stopped to remove the drill bit from the well, the average drilling rate slows down and drilling costs increase or the well is drilled with non-optimum hydraulics. Thus, it would be an advantage to be able to optimize a drilling well's hydraulic system by having the ability to change the drill bit TFA concurrently with drilling without having to remove the drill bit from the well.